Catalytic hydroprocessing refers to petroleum refining processes in which a carbonaceous feedstock is brought into contact with hydrogen and a catalyst, at a higher temperature and pressure, for the purpose of removing undesirable impurities and/or converting the feedstock to an improved or more valuable product.
Heavy hydrocarbon feedstocks can be liquid, semi-solid and/or solid at atmospheric conditions. Such heavy hydrocarbonaceous feedstocks can have an initial ASTM D86-12 boiling point of 600° F. (315° C.) or greater.
The feedstock properties that influence its hydroprocessability include: organic nitrogen content, especially basic nitrogen content; feed boiling range and end point; polycyclic aromatics content and previous processing history (i.e., straight run versus thermally cracked).
Heavy hydrocarbonaceous oils boiling in the gas oil range can be high in heteroatom content, especially nitrogen. Nitrogen content can range from about 50 ppmw to greater than 5,000 ppmw elemental nitrogen, based on total weight of the heavy hydrocarbonaceous oils. The nitrogen containing compounds can be present as basic or non-basic nitrogen species. Examples of basic nitrogen species include pyridines, alkyl substituted pyridines, quinolines, alkyl substituted quinolines, acridines, alkyl substituted acridines, phenyl and naphtha substituted acridines. Examples of non-basic nitrogen species include pyrroles, alkyl substituted pyrroles, indoles, alkyl substituted indoles, carbazoles and alkyl substituted carbazoles.
Heavy hydrocarbonaceous oils boiling in the gas oil range can have sulfur contents ranging from about 500 ppmw to about 100,000 ppmw elemental sulfur (based on total weight of the heavy hydrocarbonaceous oils). The sulfur will usually be present as organically bound sulfur. Examples of such sulfur compounds include the class of heterocyclic sulfur compounds including, but not limited to, thiophenes, tetrahydrothiophenes, benzothiophenes and their higher homologues and analogues. Other organically bound sulfur compounds include aliphatic, naphthenic and aromatic mercaptans, sulfides, disulfides and polysulfides.
Gas oil range feeds contain polycyclic condensed hydrocarbons having two or more fused rings. The rings can either be saturated or unsaturated (aromatic). For the latter, these polycyclic condensed hydrocarbons are also called polynuclear aromatics (PNA) or polyaromatic hydrocarbons (PAH). The light PNAs, with two to six rings, are present in virgin vacuum gas oil streams. The heavy PNAs (HPNA) generally contain 7-10 rings, but can contain higher amounts including 11 rings or at least 14 rings or dicoronylene (15-rings) or coronylenovalene (17-rings) or higher.
Hydrocracking is an important refining process used to manufacture middle distillate products boiling in the 250-700° F. (121-371° C.) range, such as, kerosene, and diesel. Hydrocracking feedstocks contain significant amounts of organic sulfur and nitrogen. The sulfur and nitrogen must be removed to meet fuel specifications.
Removal or reduction of the sulfur and nitrogen is also critical to the operation of a hydrocracking reactor. For certain low quality feedstocks, the nitrogen content and corresponding basic nitrogen content are most critical in being able to achieve high hydrocracking conversion rates. This is because of the strong poisoning effect that basic nitrogen compounds have on the acid sites of hydrocracking catalysts. Thus, higher basic nitrogen content will cause the need to increase the catalyst bed temperatures over time due to a decrease in catalytic activity caused by deactivation by poisoning, which shortens the cycle life of the catalyst.
Catalyst poisoning is primarily the result of strong chemisorption of impurities on active sites. Poisoning may be reversible or irreversible, depending on the strength of chemisorption of the impurity on the catalyst. Catalyst poisoning may also be selective or non-selective. Selective poisoning is commonly observed on multi-functional catalysts having different types of active sites, such as for example, hydrocracking catalysts which exhibit both cracking and hydrogenation-dehydrogenation functions. In such a case, selective poisoning may lead to the poisoning of one type of active site without affecting the other type or types.
Another mechanism of poisoning of hydroprocessing catalysts is coke or coke precursor deposition on the active catalyst sites. Light PNAs can serve as precursors in the formation of the larger PNAs. Most of the HPNAs having more than 6 fused rings are formed during the processing of heavy gas oil components under severe hydrocracking conditions, e.g., high total conversions under recycle conditions. These heavy PNAs have a deleterious effect on the performance of the hydrocracking catalysts and the hydrocracking reaction system equipment as a result of carbon deposition on the catalysts as well as in the reaction loop.
FIG. 1 is a flow scheme for a typical two-stage, high conversion hydrocracking unit. This particular flow scheme is typically used for hydroprocessing disadvantaged hydrocracker feedstocks, such as heavy vacuum gas oils and heavy coker gas oils. These feedstocks have high amounts of nitrogen, often between 500 and 2000 ppm and sulfur, often between 0.5 and 3.5 wt %, and a low API, typically between 15 and 20.
In the two-stage hydrocracking scheme illustrated in FIG. 1, a desalted crude oil feedstock 1 is distilled in an atmospheric crude distillation unit 2. The bottoms or residuum 3 from the atmospheric distillation process is then distilled in a vacuum distillation unit 4. Typical vacuum distillation units are operated to deliver a HVGO/residue cut-point of approximately 1,050° F. (566° C.). Higher cut-points (also referred to as deeper cuts) would be beneficial as this would yield a higher volume of HVGO for processing into valuable middle distillate product. However, running the vacuum distillation unit 4 at a higher cut-point means a more disadvantaged feedstock (higher particulates, more sulfur and nitrogen species and heavy polyaromatic hydrocarbons), requiring the downstream hydroprocessing units to run at higher severity levels (higher feed residence time or lower “liquid hour space velocity,” and higher temperatures), lessening the life of the catalysts.
A HVGO cut 5 from the vacuum distillation unit 4 is hydrotreated in a conventional hydrotreating reactor 6, to saturate complex naphthenic and aromatic compounds and reduce feed contaminants such as nitrogen and sulfur which, if left untreated, would otherwise poison downstream hydrocracking catalysts.
The hydrotreated HVGO 7 is then subjected to hydrocracking conditions in a first stage hydrocracker unit 8, followed by atmospheric distillation of the hydrocracked HVGO feedstock 9 in an atmospheric fractionation column 10. In a typical two-stage hydroprocessing unit, the first stage hydrocracker unit 8 is operated at a severity sufficient to achieve a 45-50% conversion.
Light ends 11 and middle distillate products such as naphtha 12, kerosene 13 and diesel 14 are recovered from the atmospheric fractionation column 10, and the atmospheric bottoms fraction 15 is subjected to further hydrocracking conditions in a second stage hydrocracker unit 16. An FCC bleed 17 from the atmospheric bottoms fraction 15 stream is passed to a standard fluidized catalytic cracking (FCC) unit 18. FCC units convert high-boiling, high-molecular weight hydrocarbon fractions of petroleum crude oils into more valuable gasoline 19, olefinic gases used for making alkylate, and other products such as naphtha. Catalysts employed in FCC units are substantially more tolerant of feedstocks containing high amounts of nitrogen, sulfur and PNAs, as compared to conventional hydrocracking catalysts.
The entire second stage hydrocracker effluent 20 is recycled back to the atmospheric fractionation column 10. This configuration requires the undesirable components (N, S, PNAs) in the atmospheric bottoms fraction 15 to be recycled to extinction within the hydrocracking loop.
However, the configuration illustrated in FIG. 1 has some disadvantages. The feed considerations for the second stage hydrocracker unit 16 take priority over the feed considerations for the FCC unit 18. Because the entire bottoms 15 from the atmospheric fractionation column 10 are passed to the second stage hydrocracker unit 16, the first stage hydrocracker unit 8 must operate at a high level of severity to ensure the feed to the second stage hydrocracker unit 16 has been converted and hydrotreated to a level high enough for the second stage hydrocracker unit 16 to accommodate the feed (e.g. to prolong the life of the catalyst in the second stage). In contrast, FCC units can accommodate heavy feeds high in nitrogen, sulfur and aromatics. This means the FCC bleed 17 in this configuration has been hydroprocessed to a greater degree than is necessary for the FCC unit to meet the FCC unit product specifications.
Typical Feed to 2nd StageTypical Feed to FCCAPI Gravity28-3321-25Sulfur, ppm<50<2000Nitrogen, ppm1-5 50-200TBP 95% Point,950-1050 (510-566)1050-1350 (566-732)° F. (° C.)
Further, this configuration is operated essentially as a full conversion zone. This means the bottom or residuum fractions are all converted in the hydrocracking units. This requires more catalyst which, in turn, requires larger reactors to be built and placed into service, adding substantial cost to the construction and operation of the hydrocracking train, both 1st and 2nd stage. In addition, more hydrogen is required to operate these larger hydrocracking units, in view of the higher severity operations, adding to the operating costs for the refiner.
Finally, because this configuration is operated as a full conversion zone, the 1st stage hydrocracking unit must be operated at high severity in order to reduce the nitrogen, sulfur and PNA to concentrations low enough for the 2nd stage to hydroprocess without deactivation. This results in shorter catalyst lifetimes and unit fouling.
Accordingly, there is a current need for a two-stage hydrocracking process capable of producing middle distillates that have reduced nitrogen, sulfur content, while simultaneously producing a 900° F.+ (482° C.+) HVGO stream useful as a feedstock to fluidized catalytic cracking unit.
There is also a current need for a two-stage hydrocracking process which utilizes less hydrogen than a conventional two-stage hydrocracking process, and which can be operated under less severe conditions than a standard two-stage hydrocracking process, thereby reducing the amount of hydrocracking catalyst and hydrogen needed to achieve the target product specifications.